Rocks with natural fractures, cracks, faults and vugs have complex multi-connected pathways for fluid flow. In these systems, fluid flow, especially to production wellbores, can change as reservoir conditions change as fluids are injected to the reservoir. In typical practice, the more detailed the characterization of the fracture network, the easier it is to optimize recovery process design and well placement to maximize the recovery factor of petroleum fluids. Furthermore, for tight rocks where hydraulic fracturing is required to enable sufficient fluid mobility for economic production, it is critical to understand the placement of the induced fractures, their connectivity, extent, and interaction with natural fractures within the system. Stress anisotropy and interactions between new fractures and natural fractures in the formation can dictate the mode, orientation and size of the hydraulic fracture network. In this study, normal deformation is coupled with fluid flow to evaluate the effect of the stress anisotropy on fracture network propagation in rock. The results demonstrate that stress anisotropy and existing natural fractures networks are playing critical roles in creating fracture-network complexity and connectivity. The model developed here assumes that the flow is single-phase and isothermal, matrix permeability is zero, and that deformation arises from small normal displacement in an infinite, homogeneous, linearly elastic medium. Specifically, the model couples fluid flow and stresses induced by fracture deformation in a plane. For this purpose, a system of equations governing fracture deformation and fluid flow through a complex fracture network is solved. The results illustrate the importance of rock properties, stress magnitude, and stress orientation on fracture complexity in unconventional naturally fractured reservoirs.

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